A significant fraction of the oil-in-place is left in the ground after primary or secondary recovery. Gas injection, sometimes referred to as gas flooding, has been used to recover this remaining oil. The terms "gas injection" and "gas flooding" as used herein will mean an oil recovery process in which the fluid injected is a hydrocarbon gas, inert gas, carbon dioxide, or steam.
The success of gas floods has been diminished by the unfavorable mobility ratio between the gas and oil. The viscosities of gas mixtures are often 10 to 100 times lower than oil and water viscosities. At these unfavorable viscosity ratios, gases finger and channel through the formation, leaving parts of the reservoir unswept. Added to this fingering is the inherent tendency of a highly mobile gas to flow preferentially through the more permeable rock sections or to gravity override in the reservoir. These basic factors --permeability variations and unfavorable mobility and density ratios--greatly reduce the effectiveness of gas floods and may make them uneconomic. One apparent remedy is to control the mobility of the injected gas.
It has been suggested that the mobility of the gas may be reduced by injecting into a formation or forming in situ a mixture of a gas and an aqueous surfactant solution. Such mixtures are commonly referred to as foams. Since the effective viscosity of foam is greater than the viscosity of its components, it has been suggested that such mixtures of gas and aqueous surfactant solution will help improve the sweep efficiency of gas drives.
Foam is a dispersion of a large volume of gas in a relatively small volume of liquid. It should be noted, however, that at reservoir conditions several gases, including CO.sub.2, exist as a dense fluid, resembling a liquid more than a gas. For this reason, the term "solvent" is sometimes used to describe the "gas" and the term "emulsion" is sometimes used to describe the solvent-water mixture.
Mobility control may be accomplished by injecting a bank of aqueous surfactant solution followed by injecting gas. Alternatively, banks of surfactant solution can be interspersed with the gas during injection to achieve a more continuous effect.
It is known that the choice of surfactant for use as a mobility control agent is of vital importance. Many surfactants reduce gas mobility too much, thus making the gas difficult to inject into the reservoir. Other surfactants don't reduce gas mobility enough, thus leading to inadequate improvement of sweep efficiency.
Conditions existing in a typical oil reservoir impose a severe challenge to surfactant performance. Most reservoirs have an aqueous phase of brine that may vary in concentration from 0.5% to 15% NaCl. Also, there may be divalent ions such as Ca.sup.++ and Mg.sup.++ present in significant concentrations (100 ppm or more). Adsorption or trapping of surfactant in viscous emulsions is another limitation. The effect of crude oil and temperature can also be deleterious if not properly taken into consideration.
Considerable effort has been made by the petroleum industry to identify surfactants with proper chemical stability, adsorption characteristics, and capability for gas-mobility reduction. Hundreds of surfactants have been screened. There continues to be a significant need, however, for improved gas mobility-control processes in which the amount of additional oil recovered as a result of injecting the surfactant and gas is sufficient to justify the cost of the process.